1. Field of the Invention
The invention relates generally to drilling wellbores through subsurface earth formations. More particularly, the invention relates to a system for automatically controlling the rate of release of a drill string to maintain a selected control parameter during drilling.
2. Background Art
Drilling wellbores through the earth includes “rotary” drilling, in which a drilling rig or similar lifting device suspends a drill string which turns a drill bit located at the bottom end of the drill string. Equipment on the rig, such as a rotary table/kelly or a top drive turns the drill string. Some drill strings may include an hydraulically operated motor to rotate the bit in addition to or in substitution of rotating the drill string from the surface. The rig includes lifting equipment that suspends the drill string so as to place a selected axial force (weight on bit—“WOB”) on the drill bit as the bit is rotated. The combined axial force and bit rotation causes the bit to gouge, scrape and/or crush the rocks, thereby drilling a wellbore through the rocks. Typically a drilling rig includes liquid pumps for forcing a fluid called “drilling mud” through the interior of the drill string. The drilling mud is ultimately discharged through nozzles or water courses in the bit. The mud lifts drill cuttings from the wellbore and carries them to the earth's surface for disposition. Other types of drilling rigs may use compressed air as the fluid for lifting cuttings.
Drilling boreholes in subsurface formations for oil and gas wells is very expensive and time consuming. Formations containing oil and gas are typically located thousands of feet below the earth surface. Therefore, thousands of feet of rock and other geological formations must be drilled through in order to establish producible wells. While many operations are required to drill and complete a well, perhaps the most important is the actual drilling of the borehole. The cost associated with drilling a well is primarily time dependent. Accordingly, the faster the desired penetration depth is achieved, the lower the cost for drilling the well. However, cost and time associated with well construction can increase substantially if wellbore instability problems or obstacles are encountered during drilling. Therefore, successful drilling requires achieving a penetration depth as fast as possible but within the safety bounds defined for the particular drilling operation.
Achieving a penetration depth as fast as possible during drilling requires drilling at an optimum rate of penetration (ROP). The rate of penetration achieved during drilling depends on many factors, however, the primary factor is weight on bit. As disclosed in U.S. Pat. No. 4,535,972 to Millheim et al., for example, rate of penetration generally increases with increasing weight on bit until a certain weight on bit (WOB) is reached. ROP decreases as additional weight on bit is applied above the certain weight. Thus, there is generally a particular weight on bit that will achieve a maximum rate of penetration for each set of drilling conditions. However, the rate of penetration of a drill bit also depends on many factors in addition to the weight on bit. For example, the rate of penetration depends upon characteristics of the formation being drilled, the speed of rotation of the drill bit (RPM), and the rate of flow of the drilling fluid, among other factors. Because of the complex nature of drilling, a weight on bit that is optimum for one set of conditions may not be optimum for another set of conditions.
One method known in the art to determine an optimum rate of penetration for a particular set of drilling conditions is known as a “drill off test,” which is disclosed, for example, in U.S. Pat. No. 4,886,129 to Bourdon. During a drill off test, a drill string supported by a drilling rig is lowered into the wellbore. When the bit contacts the bottom of the borehole, drill string weight is transferred from the rig to the bit (by releasing the drill string into the wellbore) until an amount of weight greater than the expected optimum weight on bit is applied to the bit. Then, while holding the drill string against vertical motion at the surface, the drill bit is rotated at the desired rotation rate with the fluid pumps at the desired pressure. As the bit is rotated, it cuts through the earth formations. Because the drill string is held against vertical motion at the surface, weight is increasingly transferred from the bit to the rig as the bit cuts through the earth formation. As disclosed in U.S. Pat. No. 2,688,871 to Lubinsky, by applying Hooke's law, an instantaneous rate of penetration may be calculated from the instantaneous rate of change of weight on bit. By comparing bit rate of penetration with respect to weight on bit during the drill off test, an optimum weight on bit can be determined. In typical drilling operations, once an optimum weight on bit is determined, the “driller” (the drilling rig operator) attempts to maintain the weight on bit at that optimum value during drilling.
One of the more difficult tasks performed by the driller is to maintain the WOB as nearly as possible at the most efficient value. During typical drilling operations, maintaining the WOB is performed by manually operating a friction brake to control the speed at which a drawworks winch drum releases a wire rope or cable. The wire rope, through a system of sheaves, suspends the drill string within the rig structure. There are a number of electrical (eddy current) braking devices, hydraulic braking devices and electro-hydraulic devices well known in the art that perform braking control or its functional equivalent to control the rate of drum rotation (and consequent cable release) Manual control of WOB is difficult. The driller must visually observe a weight indicator or other display, such as a mud pressure gauge, and control the drum speed, typically by operating the brake, so as to maintain the WOB or mud pressure at or close to a selected value.
Because of the obvious difficulty of manual control of WOB or related parameter, there have been many devices designed to automate at least this aspect of drilling rig operation. Typical examples of electromechanical automatic drilling devices are shown in U.S. Pat. No. 3,031,169 to Robinson et al.; U.S. Pat. No. 4,825,962 to Girault; U.S. Pat. No. 4,491,186 to Alder; U.S. Pat. No. 4,875,530 to Frink et al.; U.S. Pat. No. 4,662,608 to Ball; and U.S. Pat. No. 5,474,142 to Bowden. Another example of a brake control device is shown in a sales brochure entitled, Lidan Brake Servo Systems, Lidan Engineering AB, Jacobstorp, S-531 98, Lidköping, Sweden (2003).
The foregoing devices, as well as others known in the art, either control brake operation or control winch rotation, or both, using mechanical or electromechanical sensing devices and electrical and/or mechanical coupling of the sensing devices to the brake and/or winch controller. The foregoing devices and other electro-mechanical devices may be limited as to the particular drilling parameter that can be controlled, for example WOB, drilling fluid pressure and drum rotation speed. Further, some of the foregoing devices may require extensive modifications to the drilling rig drawworks equipment to be installed.
It is known in the art to control drilling rig operation using computers. See, for example, F. S. Young, Jr., Computerized Drilling Control, Journal of Petroleum Technology, April 1969, Society of Petroleum Engineers, Richardson, Tex. Another computerized drilling control system is disclosed in J. F. Brett et al., Field Experiences With Computer-Controlled Drilling, paper no. 20107, Society of Petroleum Engineers, Richardson, Tex. (1990). Computerized control of drilling operations has some apparent advantages, including greater flexibility over control parameters, simplified installation, faster, more accurate operation of rig equipment. Using computer control, it is also possible to operate the drilling rig equipment to maintain drilling control parameters at optimum values determined by complex control algorithms, rather than simple parameter measurements. See, for example, U.S. Pat. No. 6,192,998 to Pinckard, which is assigned to the assignee of the present invention.
Despite the apparent advantages, computer controlled drilling rig systems have not been widely used. Several reasons for the lack of wide use are disclosed in the Brett et al. reference cited above, and include imprecise control of block position using conventional drawworks control. Because of such imprecision, Brett et al. used an hydraulic lift unit to control the axial motion of the drill string, rather than a conventional drawworks. As described in the Brett et al. reference, hydraulic lift units, while effective, have been difficult to maintain and transport. Other drawworks control devices, such as disclosed in the Frink et al. '530 patent cited above, while effective and adaptable to computer control, require expensive and extensive modification of the drawworks equipment.
Adapting computer control to conventional drawworks motion control devices has also been difficult. A primary source of the difficulty is the fact that conventional drawworks friction brakes are band-type brakes. As is well known in the art, band-type brakes are self-actuating. This aspect of the typical band-type drawworks has made their response difficult to characterize. As a result, it has been believed by those skilled in the art that computer control of conventional band-type brakes is impracticable. See, for example, Boyadjieff et al., Design Considerations and Field Performance of an Advanced Automatic Driller, paper no. SPE/IADC 79827, Society of Petroleum Engineers, Richardson, Tex. (2003).
Accordingly, there exists a need for a computerized drilling rig control that is readily adapted to band-brake drawworks controls without extensive equipment modification.